1. Field of the Invention
This invention relates to a system and method for removing hydrogen sulfide from carbon dioxide, methane and other components of natural gas streams being processed into a sales gas stream. The system and method of the invention are particularly suitable to separate carbon dioxide and hydrogen sulfide when the Stinson Process is utilized for removing high concentrations of carbon dioxide and hydrogen sulfide from natural gas streams containing nitrogen.
2. Description of Related Art
Hydrogen sulfide and carbon dioxide contamination are frequently encountered problems in the production of natural gas. Transporting pipelines typically do not accept natural gas containing more than about 4% CO2 and 4 ppm hydrogen sulfide. Hydrogen sulfide is particularly problematic because it is extremely toxic to humans and is corrosive in nature. Allowing hydrogen sulfide to remain in process streams can be harmful to piping and other equipment. As such, it is desirable to remove H2S from the produced gas early in the processing.
Known methods of removing H2S and CO2 from natural gas streams include chemical solvents and physical solvents. These technologies have been well tested in the natural gas industry and the strengths and weaknesses of various chemical components used in these processes are well known to those in the industry. One such physical solvent that is well established in the industry is Selexol from Dow Chemical. With a typical Selexol process, the feed gas contacts the Selexol in a first absorber, where the majority of the CO2 and H2S in the feed stream are removed into the solvent. The CO2 and H2S are then separated through one or more reduced pressure separators and a stripper to produce a CO2 and H2S rich “acid gas” vapor stream and a “Lean” Selexol stream to be recycled back to the inlet absorber where it removes more CO2 and H2S from incoming gas. Utilization of conventional Selexol technology is used where the CO2 concentrations are generally in the 10 to 20 percent range and are used in preference to chemical processes based on the comparative installation cost and the cost of operation.
Another known method for removing both CO2 and H2S from natural gas is known as the Stinson Process, as described in U.S. Pat. No. 7,883,569 and the patents related thereto. The Stinson Process takes a dehydrated feed stream containing around 70% CO2, 20% CH4, 7% N2, and 3.5% H2S and produces a processed gas stream containing around 3% N2, 97% CH4, and 0.03% H2S and a liquid waste stream containing around 94% CO2 and 5% H2S. The CO2 and H2S are removed from the feed stream using a fractionating column, with the bottom stream containing primarily CO2 and some H2S and an overhead stream containing 31% CO2 and less than 2% H2S. The overhead stream from the fractionating column is then processed using a methanol absorption tower to separate additional CO2 and H2S and produce an intermediate processed gas stream (containing around 69% methane) as the overhead stream from the absorption tower, which is then processed through a separator to remove nitrogen and helium, resulting in a processed gas stream containing around 97% CH4 and around 0.03% H2S. This processed gas stream is then typically passed through a molecular sieve to scrub the 300 ppm H2S down to an acceptable pipeline level of less than 4 ppm for sales gas. The methanol is then recovered using a flash chamber and a methanol stripper tower, with the recovered methanol being recycled back to the methanol absorption tower. The overhead streams from the flash chamber and methanol stripper contain CO2, CH4, and H2S and are recycled back to feed the fractionating column. The liquid waste stream from the fractionating column, which contains around 94% CO2 and 5% H2S may be injected into an underground well, avoiding some of the environmental concerns associated with releasing CO2 and H2S to the atmosphere.